1. Field of the Invention
The present invention relates to the field of measurement. More specifically, the present invention, in an exemplary embodiment, relates to measurement of selected physical parameters for a predetermined environment using distributed optical sensors. More specifically still, the present invention, in an exemplary embodiment, relates to measurement of temperature, mechanical stress, pressure, vibration and mechanical strain using distributed fiber optic sensors in environments that require distributed measurements over long distances or continuous measurements where individual sensors would be prohibitive due to space constraints and/or costs.
2. Description of the Related Art
Numerous fields require precise measurements of pressure, temperature, and/or strain but prior art methods are either too expensive, too dangerous, and/or too unsuited for use, e.g. due to inference caused or generated by the method. By way of example and not limitation, many prior art sensors are electromechanical and cannot be placed into environments where gasses are volatile or into environments where either other machinery's electromagnetic interference (“EMI”) will affect the sensor or the sensor's EMI will affect the other machines.
Using the present invention to provide downhole intelligence may not only allow the industry to collect more accurate reservoir and production data, but may also allow the industry to evaluate, predict, recommend, and take actions downhole without intervention into a wellbore from the surface. For example, the production of unwanted water with oil and gas can have a significant impact on operations and economics over the life of a field. Intelligent systems can improve water separation and reinjection into the downhole environment, thus playing a vital role in water management and offering many new, significant opportunities to reduce lifting and processing costs while producing a substantial positive impact on the environment.
Faster and more accurate decisions are required to improve the performance of the field assets. Integration of a company's expertise and resources to optimize the asset life cycle will require the combination of field acquired data with knowledge management for processing, analysis and proper interpretation of the information.
New processes for drilling, completion, production, hydrocarbon enhancement, and reservoir management have been created by advancements in technology in fields such as high temperature sensing, downhole navigation systems, composite materials, computer processing speed and power, software management, knowledge gathering and processing, communications and power management. Sensor technology, in conjunction with data communications, provides on-demand access to the information necessary to achieve hydrocarbon production levels and costs goals. For example, U.S. Pat. No. 6,192,988 issued to Tubel for “Production Well Telemetry System and Method” describes a downhole production well control system comprising downhole control systems that use short hop transceivers. U.S. Pat. No. 6,192,980 issued to Tubel et al for “Method and Apparatus for the Remote Control and Monitoring of Production Wells” discloses a system adapted for controlling a plurality of production wells is also illustrative.
Fiber optic sensor technology will significantly change the reliability of downhole systems and the ability to place sensors in a wellbore. Distributed optical sensors embedded inside the fiber optic cable will allow the large sections of the well to be monitored instead of a specific zone.
Fiber optic cable and sensor technology will significantly change the reliability of downhole systems and the ability to place sensors in the wellbore. Distributed optical sensors embedded inside the fiber optic cable will allow the entire well to be monitored instead of a specific zone. The cost of monitoring wellbores during production should decrease significantly while the amount of data collected downhole and retrieved and processed at the surface should increase. Fiber optic sensor technology will complement and, in some cases, eliminate production logging runs.
By way of example and not limitation, over the last several decades, new technology development has been fundamental to maintaining the economic attractiveness of developing oil and gas reserves in spite of flat hydrocarbon prices. Monitoring and controlling the processes required to search for and produce hydrocarbons constitutes an ongoing concern in the oil and gas industry. This concern is due in part to the enormous expenses and risks associated with the execution of those processes, as well as environmental and safety factors.
By way of further example and not limitation, methane hydrates are solid, ice-like materials containing molecules of natural gas that represent a potentially significant source of natural gas. The amount of hydrates around the world is estimated to be many times the total amount of natural gas reserves.
The Gulf of Mexico contains a significant amount of methane hydrates in deep water due to the high pressure and low temperature environment conditions. However, these hydrates are not very stable and their dissociation can be slow or explosive depending on the chemical content and concentrations of the hydrates as well as changes in temperature and pressure.
As exploration and production of hydrocarbons continues to move towards deep waters such as in the Gulf of Mexico, hydrate associated seafloor stability issues need to be addressed. Gas hydrate mounds are formed along the intersections of faults with sea floor. The mounds can change significantly in a matter of days. The ability to monitor, evaluate, predict and perhaps control the seabed changes is essential for the safety exploration and production of hydrate natural gas as well as conventional hydrocarbons.
As will be familiar to those of ordinary skill in the fiber optics arts, because the functional properties of fiber sensors include remote operation, immunity to electromagnetic interference (EMI), small size, long term reliability, and capability of responding to a wide variety of measurements, fiber optics is particularly suited for use in high temperature and pressure environments. U.S. Pat. No. 6,233,746 issued to Skinner for “Multiplexed Fiber Optic Transducer for Use in a Well and Method” is illustrative of such fiber optic sensors. U.S. Pat. No. 6,233,374 issued to Ogle et al. for “Mandrel-Wound Fiber Optic Pressure Sensor” is also illustrative.
A large number of techniques using optical fibers for strain measurements have been already proposed. Interferometric methods are almost the only ones providing precision, stability and dynamic ranges which satisfy most of the applications: onboard weighing systems for road vehicles, planes or others; systems dedicated to monitor the integrity of structures; and monitoring of parameters inside the wellbores for oil and gas exploration.
Many methods of obtaining measurements using fiber optics have been proposed in the prior art. As will be familiar to those of ordinary skill in the fiber optic arts, the Raman effect is the appearance of weak lines in the spectrum of light scattered by a substance which has been illuminated by a monochromatic light. The lines occur close to, and on each side of, the main spectral lines, and arise from the inelastic scattering of the photons with atomic or molecular vibrations or rotations in the scattering material. By analogy with the terminology used in fluorescence, the lines corresponding to a loss of energy are called Stokes lines and those corresponding to a gain of energy are called AntiStokes lines.
The frequency difference between the incident photon and the scattered photon gives an energy separation that can be measured. By measuring the energy shift of the scattered photons, the structure of the system can be determined. For example, temperature information related to the system may be obtained by measuring the intensity of the reflected photon at the surface.
Fiber optic gratings system have been proposed for fiber optic sensors that have the potential for use in wellbore applications. The fiber gratings are constructed by doping the core of an optical fiber with material such as germanium. When exposed to light, the index of refraction of the optical core of silica based fiber with appropriate core dopants have been observed to have a modified index of refraction. Use of phase masks or interfering laser beams has been demonstrated to produce multiple variations in the index of refraction along the length of the fiber core producing an internal grating structure. Adjusting the spacing of the period during formation of the fiber grating changes its spectral transmission and reflection characteristics. When a fiber grating is exposed to an environmental effect such as pressure the length of the optical fiber is changed, as is the period of the fiber grating.
For many applications it is necessary to measure both temperature and strain simultaneously. U.S. Pat. No. 5,380,995 to Udd et al. for “Fiber Optic Grating Sensor Systems for Sensing Environmental Effects” describes how using two overlaid fiber gratings at different wavelengths such as 1.3 and 1.5 microns may be used to simultaneously measure two environmental parameters such as strain and temperature at a single point. M. G. Xu, H. Geiger, and J. P. Dakin, in “Multiplexed Point and Stepwise Continuous Fiber Grating Based Sensors: Practical Sensor for Structural Monitoring?”, Proceedings of SPIE, volume 2294, p. 6980, 1994, also demonstrated the simultaneous measurement of strain and temperature using 1.3 and 0.85 micron wavelengths and overlaid fiber gratings for point measurements.
In order to make complete measurements of strain internal to a structure it is often necessary to measure all three strain components. There is a continuing need to measure other environmental effects such as transverse strain at a single point and to integrate such fiber grating sensors into practical and economical sensor systems that can be manufactured using available components.
The present system can be used to simultaneously measure and continuously monitor many individual sensors placed along a fiber length. This enables the detection and accurate measurement of both the sensed parameter and environmental effect on each sensor. A normal fiber grating is sensitive to temperature, transverse strain and longitudinal strain effects. Transverse strain effects are particularly important when the fiber sensors are embedded into materials subject to loading such as advanced organic and metallic composite structures. More specifically, some such known sensors use optical fibers in which diffraction gratings have been inscribed, typically known as “Bragg” gratings. The term “Bragg Grating” is used herein below for any diffraction grating, without the field of the present invention being restricted to Bragg Gratings only. By way of example, such sensors are described in U.S. Pat. No. 6,212,306 issued to Cooper et al. for “Method and Device for Time Domain Demultiplexing of Serial Fiber Bragg Grating Sensor Arrays.”
As will be understood by those of ordinary skill in the fiber optics measurement arts, a diffraction grating inscribed in the core of an optical fiber is constituted by a succession of periodic changes in the refractive index of the core of the fiber over a given length along the axis of the optical fiber. The cumulative effect of these changes on a light signal transmitted by the fiber is to reflect a significant portion of the signal back towards its injection end. Further, this takes place around a wavelength referred to as the “central” reflection wavelength of the diffraction grating. The central reflection wavelength is a function of the pitch of the grating and of the initial refractive index of the optical fiber core, i.e. its index before the grating was inscribed. For the remainder of the signal, the refraction grating is substantially transparent. Thus, a diffraction grating inscribed in the core of an optical fiber acts like a narrow bandstop filter for the light signal conveyed by the core. U.S. Pat. No. 6,208,776 issued to Pohaska et al. for “Birefringent Fiber Grating Sensor and Detection System” is illustrative of such systems.
In the spectrum reflected from the Bragg grating, this phenomena gives rise to a peak over a range centered on the central reflection wavelength that is relatively narrow thereabout. In the spectrum transmitted through the grating, this also gives rise to a corresponding notch at the said wavelength.
As will be familiar to those of ordinary skill in the optics measurement arts, a Fabry-Perot interferometer includes two semi-reflective mirrors spaced substantially parallel to one another by a given distance so as to define a Fabry-Perot cavity having transmittance or reflectance properties which are affected by a physical parameter. The physical parameter causes the spectral properties of the light signal to vary in response to changes such as pressure. The Fabry-Perot interferometer uses at least one multimode optical fiber for transmitting the light signal into the Fabry-Perot cavity and for collecting at least a portion of the light signal back as a reflected signal at the surface. The sensor is placed in a pressure containing container with a non-intrusive, metal embedded fiber optic pressure sensor. A Fabry-Perot Interferometer is arranged in a terminated, single mode or multi mode fiber to function as a strain gauge. The fiber Fabry-Perot Interferometer (FFPI) is embedded in a metal or other material that isolate the environment from the fiber element part which may be disposed in a wall of the pressure containing container. The metal part and FFPI experience a longitudinal strain in response to the pressure in the container. In another aspect of the invention, a nonintrusive fiber containing the FFPI may be embedded along the axis of a metal housing. The housing may be used to attach a part or structure, which is directly exposed to the pressure, to the wall of the container. Consequently, the housing and FFPI experience a longitudinal strain in response to the pressure on the part or structure. U.S. Pat. No. 6,137,812 issued to Hsu et al. for “Multiple Cavity Fiber Fabry-Perot Lasers” is illustrative.
The need for accurate measurement of parameters is important to the operation of many industries. For example, large vessels such as ocean ships often present hostile environments for electrical sensors, but these large vessels need sensors to provide ongoing, real-time data on stresses present in the vessel structure, e.g. pressure, strain, and the like.
By way of example and not limitation, oil and gas E&P requires precise measurement of exploration data as well as production data. For example, in the hydrocarbon industry the outside of the casing deployed inside of the well is filled with cement. The cement provides a barrier between hydrocarbon producing zones and non-producing zones preventing oil, gas and water from migrating into other geological zones. The condition of the cement is critical in determining the barrier quality. The production of hydrocarbons may also cause the formations to compact, placing a burden on the casing and cement and sometimes causing the casing to fail which creates a potential hazardous condition and causes production to stop. The fiber system of the present invention can be used to monitor for unusual strains or temperature variations that may indicate that the casing is under abnormal strain and/or that fluids may be leaking for one formation to another.
In the prior art, distributed fiber optic sensing cables have been deployed in wellbores to monitor the temperature profile of the well. These fiber optic cables may be inserted into a well such as by pumping it into the well through a ¼″ control tube that is assembled along the production tubing.
There is therefore a need for a system and method for signal generation using discrete or distributed acoustic or strain fiber optics sensors embedded or externally attached to a fiber optic cable because fiber optics highly minimizes the risks attendant with electrical sensors in hostile environments. In such systems acoustic information may be used to provide information related to porosity, travel time within the geological formations or other desired statuses of the geological formation during drilling of wells or production of hydrocarbons from the wellbore. The acoustic signals may use a combination of devices to generate or detect the acoustic signals in and out of the wellbore. The signal may be generated using light traveling through a fiber optics medium. The light can generate enough acoustic signals that can be coupled to the medium to be identified. The receivers can be hydrophones, geophones, fiber optics light system, piezo based sensors that can detect the acoustic signal as it travels through the formation, tubing, casing or cement in the wellbore.
Once a well can not produce enough hydrocarbons economically, the well is shut in and abandoned. However, parameters inside the wellbore such as water migration and leaks of fluids or gases from one zone to another have to be monitored. Also, the integrity of the structure has to be monitored to assure that the well structure remains sound. Accordingly, there is a need for a system and method of distribution of individual sensors located throughout a wellbore to monitor subsidence of the formations or wellbore structure after the well has been abandoned or stop producing hydrocarbon or has been shut in.
In the prior art, compressive strength measurements are often taken using what is known as an Ultrasonic Cement Analyzer (UCA). The UCA was developed to measure the compressive strength of a cement slurry as it sets when subjected to simulated oil field temperatures and pressures. Set time and compressive strength are calculated from measured transit time via empirically developed equations. Unfortunately thickening time tests and compressive strength tests do not tell the whole story. Thickening time is a test which only simulates actual job conditions up to the predicted placement time. After allowing for test accuracy variation, a thickening time longer than the placement time allows for some margin of safety but only for continuous pumping at a lower than predicted rate. Thickening time “safety factors” do not directly relate to how long a slurry can remain static and still be moved after an inadvertent or intentional shutdown during placement. With respect to what actually takes place downhole, a thickening time measurement provides information on what happens up to the end of placement time. A thickening time of six hours tells nothing about what change will occur when the slurry is allowed to remain static after pumping. The compressive strength test shows the degree of hydration and set that will occur eight, twelve, or twenty-four hours after placement.
In addition to gas flows through a cement slurry many in the industry are using static gel properties to control the flow of water. Some believe water flows through cement slurries to be the most critical problem encountered while drilling, for example, in deep water in the Gulf of Mexico. Static gel strength development can be quantified and utilized to design slurries that prevent undesirable water flow.
Different measurement systems have heretofore been employed for determining static gel strength. By way of example and not limitation, static gel strength has also been measured by determining the pressure drop across a length of tubing. The basic setup of such an apparatus allows for the circulation of the test slurry through a small diameter tubing. After placement, the slurry is pressurized with water to the test pressure. A sensitive pressure drop transducer measures the pressure drop of the cement as it gels from the entrance to the exit of the tubing. As the cement gels, a corresponding pressure drop will be observed.
The foregoing problems are aggravated in offshore wells which are completed in deep cold water. Such wells include conductor pipes which are cemented from the seafloor or mud line to a depth generally under about two thousand feet below the mud line.
When cementing conductor string casing in the subterranean formation adjacent to the seafloor, the cold temperature of the cement composition after being pumped through the seawater causes the cement composition hydration to be slowed and the transition time to be extended, and as a result, the cement composition often allows the influx of water and other fluids into the annulus. These conditions can lead to cementing job failure, costly remedial work, and increased expense and rig time.
Sensor technology is necessary to evaluate and monitor cement integrity during the hydration process, during the production of hydrocarbons from the wellbore to the surface, and after the well has been abandoned, in part because cement in wells, and particularly the set cement forming the cement sheath in the annulus of high temperature wells, often fails due to shear and compression stress exerted on the set cement. The term “high temperature well” as used herein means a well wherein fluids injected into the well or produced from the well by way of the well bore cause a temperature increase of at least about 100° F. over initial cement setting conditions. The stress referred to herein is defined as the force applied over an area resulting from a strain caused by the incremental change of a body's length or volume
When stresses are exerted on the set cement in the well bore, the set cement can fail in the form of radial or circumferential cracking of the cement as well as in the break down of the bonds between the cement and pipe or between the cement and the formation. The failure of the set cement (due to the loss of hydraulic seal of the annulus) can result in lost production, environmental pollution, hazardous rig operations and/or hazardous production operations. The most common hazard is the presence of pressure at the well head in the form trapped gas between casing strings.
Additionally, there is a need for intelligent structures placed as sensors outside the casing to monitor different events that occur during the life of the well. These events may include monitoring of the cement process of the well, subsidence of the formation and settling of the cement in the borehole, monitoring cracks and leaks created in the cement to determine if a cement rework job will be necessary, monitoring corrosion of the casing or tubing monitoring to aid in determining if there will be a potential interface between section of the well that need to stay separate from each other, and measuring formation parameters using acoustic signals, strain or pressure signals generated by sources inside and/or outside the wellbore.